Field
The present application relates broadly to systems and methods of hydrocarbon recovery employing an injection well to inject fluids into a subterranean formation and a production well to produce hydrocarbons from the subterranean formation. More particularly, the present application relates to such systems and methods where the injection well and the production well employ multiple tubing strings.
Description of Related Art
There are many petroleum-bearing formations from which oil cannot be recovered by conventional means because the oil is so viscous that it will not flow from the formation to a conventional oil well. Examples of such formations are the bitumen deposits in Canada and the United States and the heavy oil deposits in Canada, the United States, and Venezuela. In these deposits, the oil is so viscous under the prevailing temperatures and pressures within the formations that it flows very slowly (or not at all) in response to the force of gravity. Heavy oil is an asphaltic, dense (low API gravity) and viscous oil that is chemically characterized by asphaltene content. Most heavy oil is found at the margins of geological basins and is thought to be the residue of formerly light oil that has lost its light molecular weight components through degradation by bacteria, water-washing, and evaporation.
In a steam assisted gravity drainage (SAGD) process, heavy oil is typically recovered by injecting saturated steam into the heavy oil reservoir utilizing one or more horizontal injection wells. The injection process produces a steam chamber within the reservoir. At the edges of the steam chamber, heat transfer is accomplished by the condensation of steam and conductive heat transfer, which reduces the viscosity of the heavy oil in this region and allows it to flow downward by gravity drainage. A horizontal production well is located below the horizontal injection well. The steam is typically injected into the reservoir for a period of time prior to production and continuously during production. Mobilized oil and condensed steam flows to the lower horizontal production well, where it is pumped by artificial lift (e.g., gas lift, progressing cavity pump, electrical submersible pump (ESP)) to the surface.
A necessary condition for efficient recovery of the heavy oil in a SAGD operation is the creation of a uniform steam chamber along the length of the horizontal injection well. If only a fraction of the heavy oil surrounding the injection well is heated, then only a fraction of the surrounding heavy oil will be mobilized. The efficiency of steam utilization can be aided by maintaining a cooler region nearer the production wellbore to discourage escape of steam from the steam chamber. This is often referred to as steam-trap control. In field practice, the continued existence of the liquid pool is monitored by examining the temperature difference between the injected steam and produced fluids, called the interwell subcool or subcool temperature. The 2005 publication by Gates et al. entitled “Steam-Injection Strategy and Energetics of Steam-Assisted Gravity Drainage,” SPE/PS-CIM/CHOA 97742 presented at the 2005 SPE International Thermal Operations and Heavy Oil Symposium, Calgary, Alberta, Canada, 1-3 Nov. 2005, describes maintaining the interwell subcool temperature at a temperature between 15 and 30° C.
The 2009 publication by Gotawala and Gates entitled “SAGD Subcool Control with Smart Injection Wells,” SPE 122014, Jun. 8, 2009 evaluated the use of Proportional-Integral-Derivative (PID) feedback control of inflow control valve (ICV) settings to control steam injection pressures along a set of six intervals of a horizontal injector well to promote subcool temperatures of the six intervals to be within a specified value. In this paper, the ICVs are intelligent completion equipment that are located downhole in the horizontal injection well and distributed over the horizontal injection well to allow for the control of steam injection rates along six intervals of the horizontal injection well. Subcool temperatures over these six intervals of the injection well and corresponding intervals of the lower production well were considered, each with its own steam injection rate dictated by a downhole ICV. The PID feedback control of the downhole ICVs changed the steam injection rate for each interval by modeling each ICV as a separate well and adjusting the steam injection pressure in each well in order to promote a subcool target over the six intervals of the injection well and production well. This enabled more uniform steam chamber growth, resulting in more oil production with reduced steam injection.
SAGD operations with wells incorporating inflow control devices (ICDs) and flow control valves (FCVs) under feedback control, looped multi-segment well topology and pressure/rate control at several points internal to the wellbore have been discussed in Stone et al, “Dynamic and Static Thermal Well Flow Control Simulation,” SPE 130499, Jun. 14, 2010, and Stone et al., “Dynamic SAGD Well Flow Control Simulation,” SPE 138054, Oct. 19, 2010. The multi-segment well topologies include a dual-tubing configuration for the injection well and the production well as shown in FIG. 1. Such a dual-tubing configuration is described in Handfield et al, “SAGD Gas Lift Completions and Optimization: A Field Case Study at Surmont,” SPE 117489, Journal of Canadian Petroleum Technology, Volume 48, No. 11, November 2009.